In natural gas transmission operations, wellhead fluids are processed in a gas-oil separation plant (GOSP), to produce dry crude, water, gas and hydrocarbon condensates. The wellhead fluids first enter a high pressure production trap (HPPT) where the gas and some of the water is separated from the crude oil. The remaining oil/water emulsion flows into a low pressure production trap (LPPT) where the oil is flashed at a lower pressure and more gas is separated. The oil/water emulsion is then pumped through a dehydrator and desalter to remove sufficient water and salt to produce product specification crude oil.
The gas from the low pressure production trap is compressed to the pressure of the high pressure production trap and both streams of gas are combined, further compressed and sent to gas plants (GP). In the gas plants, the gas is sweetened to remove sulfur, and sale gas and NGL are produced.
Historically, during the early stages of oil production from a new field in the middle east, only “pilot” GOSPs were required. This is because very little water was produced with the oil and all associated gas was flared. During the late 1970's and early 1980's, the industry decided to develop gas production to generate power for use in petrochemical industries. To that end, GOSPs were upgraded with installation of with a “gas gathering system”, the function of which was to efficiently transfer gas from the GOSPs to the gas plants.
In the early designs of the prior art, a typical GOSP had one low pressure (“LP”) gas compressor with its auxiliaries and two high pressure (“HP”) compressors with one common suction drum. The gas leaving the HP gas compressor entered a shell and tube heat exchanger and then went into a fin-type air cooler having a fan that was designed to decrease the gas temperature to 80° F. in the winter and 133° F. during the summer months. The gas then went into the discharge drum where liquid was dropped. In the final stage, the exit gas entered the cool side of the heat exchanger with a controlled bypass line around it. The GOSP exiting gas temperature was regulated by this control loop. When the GOSP exiting gas temperature dropped below the set point, a valve closed to force more exit gas to flow through the heat exchanger to pick up more heat and raise its temperature. The process was reversed if the temperature exceeded the desired value.
The gas gathering system was originally designed so that the gas leaving each GOSP would remain in the single-phase, dry gas mode until it reached the gas plant. This was accomplished by superheating the gas entering the pipeline network to prevent condensation of any of its components during transport.
The final gas temperature was controlled at 165° F. throughout the year, with 165° F. chosen primarily to assure that the gas mixture would have sufficient superheat to overcome the Joule-Thompson effect that occurred whenever the HP gas compressor recycle valve opened. Since the recycle went directly to the suction side or intake line of the compressor, the recycled gas had to be superheated to prevent any damage to the compressor. A temperature of 165° F. allows about 32° F. for the Joule-Thompson effect to occur before liquid condensate is formed and drawn into the suction side of the gas compressor during the hottest day of the year.
Operations of the system at temperatures above 130° F. proved to degrade the external pipe wrap tape, shortening the life of the tape wrap and necessitating its more frequent repair or replacement.
After this prior art gathering system was operated for many years, it was determined that the fluid steam in the pipeline system could not be maintained in the single-phase dry gas mode 100% of the time. Although originally designed for a single-phase dry gas mode of operation, flow regime, pressure and temperature changes caused a consequent condensation or “liquid drop”. The dropped liquid eventually caused corrosion at points in the gas gathering pipeline and repairs were costly.
On the basis of field studies, it was concluded that the gas gathering pipeline network had to operate under various conditions, and 100% single-phase dry gas could not be maintained at all times. The operational mode was changed to two-phase flow from the inlet of the pipeline to the network terminus with addition of a diesel-based corrosion inhibitor in order to protect the pipeline. This was achieved by injecting corrosion inhibitors into the gas streams leaving each GOSP. Diesel oil was injected to saturate the gas stream and change the phase envelope to include the inlet conditions of the stream.
Since the exit gas containing the corrosion inhibitor was in two phases, a film containing corrosion inhibitor formed on the internal pipeline surface. This film acts as a medium for the active ingredients. As a result, the active ingredients travel throughout the system and thereby ensure protection of the pipeline in case condensation forms.
It was also determined that the amount of enhanced corrosion inhibitor required is directly proportional to the temperature of the gas stream. At 165° F. each one million standard cubic feet (“MMSCF”) of gas require about one gallon of the diesel-corrosion inhibitor mixture to become saturated and at 130° F. only 0.5 gallon per MMSCF is required for saturation. See FIG. 1. To assure adequate protection, the prior art recommended that the rate of addition should not be lower than 0.5 gallon per MMSCF of gas.
It has been recognized that reducing chemical usage in general can be beneficial to the environment and can also produce substantial cost savings. It is therefore an object of the present invention to provide an improved method of adding corrosion inhibitor compositions that will be more cost effective and reduce chemical usage, and will also be automatated to reduce human error and labor spent on this task.
It is another specific object of this invention to provide an improved process for controlling the temperature and thereby the amount of corrosion inhibitor composition added to a gas stream for transmission from a GOSP.
A further object of the invention is to provide a process and apparatus for reducing the superheated gas temperature to below 165° F., while effectively saturating the gas with less than 1 gallon per MMSCF of corrosion inhibitor.